There are numerous methods, techniques and innovations designed to improve the oil and gas drilling process. Many of these involve feedback of various measured downhole parameters that are communicated to the surface to enable the driller to more efficiently, safely or economically drill the well. For example, U.S. Pat. No. 6,968,909 to Aldred et al. teaches a control system that combines measurement of downhole conditions with certain aspects of the operation of the drillstring. These downhole measurements are conveyed to the surface by well-known standard telemetry methods where they are used to update a surface equipment control system that then changes operation parameters. Closed loop two-way communication techniques like this, however, rely on the adequate detection at the surface of the telemetered parameters. It is standard in the drilling industry to control certain parameters of the downhole telemetry transmitter by downlinking appropriate commands from the surface. For example, changing the downhole drilling fluid pressure in a prescribed manner by changing the flow rate of the drilling fluid and subsequently monitoring this by a downhole pressure gauge is a common technique. Problems associated with this and similar downlinking techniques include false detection, slowing of the drilling process and the need to include human intervention in the process.
There are at present two standard telemetry techniques in common use—data conveyed via pressure waves in the drilling fluid and data conveyed via very low frequency electromagnetic waves, both originating at a downhole transmitter. Another telemetry technique beginning to emerge in the drilling arena is to convey the data via acoustic waves travelling along the drillpipe. All three technologies suffer from noise associated with the drilling operation, and all three similarly suffer signal attenuation at the surface as the well bore increases in length. These problems are illustrated herein by discussing some of the issues associated with the utilization of acoustic transmissions to transfer data from downhole to an acoustic receiver rig at the surface.
The design of acoustic systems for static production wells has been reasonably successful, as each system can be modified within economic constraints to suit these relatively long-lived applications. The application of acoustic telemetry in the plethora of individually differing real-time drilling situations, however, is less widespread. This is primarily due to it presently being an emerging technology and because of specific problems related to the increased in-band noise due to certain drilling operations, and unwanted acoustic wave reflections associated with downhole components such as the bottom-hole assembly (or “BHA”), typically attached to the end of the drillstring. The problem of communication through drillpipe is further complicated by the fact that drillpipe has heavier tool joints than production tubing, resulting in broader stopbands; this entails relatively less available acoustic passband spectrum, making the problems of noise and signal distortion even more severe. As the well is drilled and the amount of drillpipe increases there is a general degradation of the available acoustic passband properties, primarily through two effects: the non-identical dimensions of the drillpipes due to manufacturing tolerances and recuts of tool joints will narrow and distort the acoustic passband; the acoustic signal attenuation increase is directly related to the number of drillpipes.
The amount of drillpipe in the well is directly related to the ‘measured depth’ (MD), in contrast to the ‘true vertical depth’ (TVD), i.e. the vertical depth used in calculating the hydrostatic pressure in a well. Attenuation is also a function of the amount of wall contact with the drillpipe because this contact provides a means of extracting energy from acoustic waves travelling along the pipe. Typical attenuation values may range from 12 dB to 35 dB per kilometer.
Noise from many sources must be dealt with. For example, the drill bit, mud motor and the BHA and pipe all create acoustic noise, particularly when drilling. The downhole noise amplitude generally increases as rotation speed and/or the drilling rate of penetration increases. On the surface, noise originates from virtually all moving parts of the rig. Dominant noise sources include diesel generators, rotary tables, top drives, pumps and centrifuges.
Thus it is evident that channel issues and noise problems will increase with the measured depth, drilling rate and rotary speed.
In summary, the challenges to be met for acoustic telemetry in drilling wells include:                Restricted channel bandwidth due to the drillstring passband structure (see U.S. Pat. No. 5,128,901 to Drumheller)        Channel centre shifts        Dynamically changing channel properties        Downhole noise due to drillpipe movements        Downhole noise due to mud motor and/or drill bit activity        Surface noise due to rig components such as diesel generators, rotating tables, and top drives        
Channel impairments generally degrade the signal's amplitude and/or phase integrity, while noise impedes the receiver's ability to detect what signal there is. A very simple metric that is used in these circumstances is the signal-to-noise ratio (SNR). Maximizing the SNR is a telemetry objective. Certain embodiments of the present invention teach a novel means of enabling the automatic control of various transmitter parameters so as to maintain the SNR available at surface at or above a minimum achievable and predetermined threshold in the acoustic drilling telemetry environment. It can equally be applied to the other major telemetry means indicated herein as they have similar SNR issues resulting from their own associated telemetry channel impairments.